NLS2025008, Technical Specification Bases Changes

Technical Specification Bases Changes

ML25107A054
Person / Time
Site:	Cooper
Issue date:	04/17/2025
From:	Dewhirst L Nebraska Public Power District (NPPD)
To:	Office of Nuclear Reactor Regulation, Document Control Desk
References
NLS2025008
Download: ML25107A054 (1)

Text

Nebraska Public Power District Always there when you need us NLS2025008 April 17, 2025 U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, D.C. 20555-0001

Subject:

Technical Specification Bases Changes Cooper Nuclear Station, Docket No. 50-298, Renewed License No. DPR-46 The purpose of this letter is to provide changes to the Cooper Nuclear Station (CNS) Technical Specification Bases implemented without prior Nuclear Regulatory Commission approval.

In accordance with the requirements of CNS Technical Specification 5.5.1 0.d, these changes are provided on a frequency consistent with 10 CFR 50.71(e). The enclosed Bases changes are for the time period from February 23, 2023, through February 22, 2025. Also enclosed are filing instructions and an updated List of Effective Pages for the CNS Technical Specification Bases.

This letter contains no commitments. If you have any questions regarding this submittal, please contact me at (402) 825-5416.

Sincerely,

~

>~~*

_,:.. /

/

~

. J' J /. -;;?.. --

Brian Stander for Linda Dewhirst Regulatory Affairs and Compliance Manager

/bk

Enclosure:

Technical Specification Bases Changes cc:

Regional Administrator, w/enclosure USNRC - Region IV Cooper Project Manager, w/enclosure USNRC - NRR Plant Licensing Branch IV Senior Resident Inspector, w/enclosure USNRC-CNS NPG Distribution, w/o enclosure CNS Records, w/enclosure COOPER NUCLEAR STATION P.O. Box 98 / Brownville, NE 68321-0098 Telephone: (402) 825-3811 / Fax: (402) 825-5211 www.nppd.com

NLS2025008 Enclosure Page 1 of 32 TECHNICAL SPECIFICATION BASES CHANGES

FILING INSTRUCTIONS Technical Specifications Bases REMOVE INSERT List of Effective Pages List of Effective Pages (All 7 pages) dated 01/18/23 (All 7 pages) dated 11/13/24 Page B 3.0-6; dated 12/09/20 Page B 3.0-6; dated 08/02/23 Page B 3.0-17; dated 12/09/20 Page B 3.0-17; dated 08/02/23 Page B 3.7-10; dated 05/17/17 Page B 3.7-10; dated 08/02/23 Page B 3.3-16; dated 04/10/19 Page B 3.3-16; dated 04/05/24 Page B 3.3-17; dated 04/10/19 Page B 3.3-17; dated 04/05/24 Page B 3.3-18; dated 11/25/12 Page B 3.3-18; dated 04/05/24 Page B 3.3-19; dated 11/25/12 Page B 3.3-19; dated 04/05/24 Page B 3.3-45; dated 11/25/12 Page B 3.3-45; dated 10/22/24 Page B 3.3-141; dated 09/19/18 Page B 3.3-141; dated 11 /13/24 Page B 3.3-148; dated 09/19/18 Page B 3.3-148; dated 11/13/24 Page B 3.4-36; dated 01/06/21 Page B 3.4-36; dated 11/15/23 Page B 3.4-37; dated 01/06/21 Page B 3.4-37; dated 11 /15/23 Page B 3.4-38; dated 01/06/21 Page B 3.4-38; dated 11 /15/23 Page B 3.6-73; dated 05/17/17 Page B 3.6-73; dated 02/22/24 Page B 3.6-74; dated 05/17/17 Page B 3.6-7 4; dated 02/22/24 Page B 3.7-10; dated 05/17/17 Page B 3. 7-1 0; dated 08/02/23 Page B 3.8-31; dated 04/03/19 Page B 3.8-31; dated 08/07/24 Page B 3.8-32; dated 02/07/13 Page B 3.8-32; dated 08/07 /24 Page B 3.8-33; dated 04/03/19 Page B 3.8-33; dated 08/07 /24 Page B 3.8-34; dated 04/03/19 Page B 3.8-34; dated 08/07/24 Page B 3.8-35; dated 04/03/19 Page B 3.8-35; dated 08/28/24 Page B 3.8-36; dated 04/03/19 Page B 3.8-36; dated 08/28/24 Page B 3.8-37; dated 02/07 /13 Page B 3.8-37; dated 08/28/24 Page B 3.8-41; dated 05/17 /17 Page B 3.8-41; dated 10/23/24

LIST OF EFFECTIVE PAGES - BASES Page No.

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Revision No./Date 09/21/18 B3.1-15 6/10/99 ii 12/19/19 B3.1-16 12/03/09 iii 09/21/18 B 3.1-17 6/10/99 iv 09/21/18 B3.1-18 07/16/08 B3.1-19 05/17/17 B 2.0-1 07/01/20 B 3.1-20 05/17/17 B 2.0-2 07/01/20 B 3.1-21 01/06/12 B 2.0-3 07/01/20 B 3.1-22 0

B 2.0-4 07/01/20 B3.1-23 0

B 2.0-5 07/01/20 B 3.1-24 0

B 2.0-6 07/01/20 B 3.1-25 05/09/06 B 2.0-7 07/01/20 B3.1-26 05/17/17 B 2.0-8 09/25/09 B 3.1-27 05/09/06 B 3.1-28 12/18/03 B 3.0-1 12/09/20 B 3.1-29 0

B 3.0-2 10/15/19 B3.1-30 0

B 3.0-3 12/09/20 B 3.1-31 0

B 3.0-4 12/09/20 B 3.1-32 0

B 3.0-5 12/09/20 B 3.1-33 05/17/17 B 3.0-6 08/02/23.

B3.1-34 07/16/08 B 3.0-7 12/09/20 B 3.1-35 07/16/08 B 3.0-8 12/09/20 B3.1-36 07/16/08 B 3.0-9 03/31/21 B 3.1-37 05/17/17 B 3.0-10 12/09/20 B 3.1-38 07/16/08 B 3.0-11 12/09/20 B3.1-39 09/25/09 B 3.0-12 09/18/09 B 3.1-40 04/10/15 B 3.0-13 03/31/21 B 3.1-41 09/25/09 B 3.0-14 09/18/09 B 3.1-42 05/17/17 B 3.0-15 12/09/20 B 3.1-43 05/17/17 B 3.0-16 12/09/20 B 3.1-44 08/09/17 B 3.0-17 08/02/23 B 3.1-45 05/17/17 B 3.0-18 12/09/20 B 3.1-46 09/25/09 83.0-19 12/09/20 B 3.1-47 09/25/09 B 3.1-48 0

B 3.1-1 6/10/99 B 3.1-49 05/17/17 B 3.1-2 6/10/99 B 3.1-50 05/17/17 B 3.1-3 6/10/99 B 3.1-51 09/25/09 B 3.1-4 6/10/99 B 3.1-5 6/10/99 B 3.2-1 09/11/15 B 3.1-6 6/10/99 B 3.2-2 09/11/15 B3.1-7 12/18/03 B 3.2-3 05/17/17 B 3.1-8 12/18/03 B 3.2-4 07/01/20 B 3.1-9 6/10/99 B 3.2-5 07/01/20 B3.1-10 6/10/99 B 3.2-6 07/01/20 B 3.1-11 6/10/99 B 3.2-7 09/11/15 B 3.1-12 12/18/03 B 3.2-8 09/11/15 B 3.1-13 12/18/03 B 3.2-9 09/11/15 B3.1-14 6/10/99 B 3.2-10 05/17/17 Cooper 1

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B 3.6-63 11/02/17 B3.6-16 1

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B 3.9-20 0

B 3.10-37 0

B 3.9-21 05/17/17 B 3.10-38 05/17/17 B 3.9-22 0

B 3.10-39 05/17/17 B 3.9-23 0

B 3.9-24 01/06/21 B 3.9-25 05/17/17 B 3.9-26 05/17/17 B 3.9-27 0

B 3.9-28 0

B 3.9-29 01 /06/21 B 3.9-30 05/17/17 B 3.10-1 11/06/06 B 3.10-2 09/19/18 B 3.10-3 11/06/06 B 3.10-4 11/06/06 B 3.10-5 11/06/06 B 3.10-6 0

B 3.10-7 0

B 3.10-8 0

B 3.10-9 0

B 3.10-10 05/17/17 B 3.10-11 0

Cooper 7

11/13/24

BASES LCO Applicability B 3.0 LCO 3.0.4 (continued)

Cooper LCO 3.0.4.b allows entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components 1 consideration of the results, determination of the acceptability of entering the MODE or other specified condition in the Applicability, and establishment of risk management actions, if appropriate.

The risk assessment may used quantitative, qualitative, or blended approaches, and the risk assessment will be conducted using the plant program, procedures, and criteria in place to implement 10 CFR 50.65(a)(4), which requires that risk impacts of maintenance activities be assessed and managed. The risk assessment, for the purposes of LCO 3.0.4.b, must take into account all inoperable Technical Specification equipment regardless of whether the equipment is included in the normal 10 CFR 50.65(a)( 4) risk assessment scope. The risk assessments will be conducted using the procedures and guidance endorsed by Regulatory Guide 1.160, "Monitoring the Effectiveness of Maintenance at Nuclear Power Plants." Regulatory Guide 1.160 endorses the guidance in Section 11 of NUMARC 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants." These documents address general guidance for conduct of the risk assessment, quantitative and qualitative guidelines for establishing risk management actions, and example risk management actions. These include actions to plan and conduct other activities in a manner that controls overall risk, increased risk awareness by shift and management personnel, actions to reduce the duration of the condition, actions to minimize the magnitude of risk increases ( establishment of backup success paths or compensatory measures), and determination that the proposed MODE change is acceptable. Consideration should also be given to the probability of completing restoration such that the requirements of the LCO would be met prior to the expiration of ACTIONS Completion Times that would require exiting the Applicability.

LCO 3.0.4.b may be used with single, or multiple systems and components unavailable. NUMARC 93-01 provides guidance relative to consideration of simultaneous unavailability of multiple systems and components.

The results of the risk assessment shall be considered in determining the acceptability of entering the MODE or other specified condition in the Applicability, and any corresponding risk management actions. The LCO 3.0.4.b risk assessments do not have to be documented.

B 3.0-6 08/02/23

BASES SR 3.0.3 (continued)

Cooper SR Applicability B 3.0 particular SR, but previous successful performances of the SR included in the relay contact; the adjacent, physically connected relay contacts were tested during the SR performance; the subject relay contact has been tested by another SR; or historical operation of the subject relay contact has been successful. It is not sufficient to infer the behavior of the associated equipment from the performance of similar equipment. The rigor of determining whether there is a reasonable expectation a Surveillance will be met when performed should increase based on the length of time since the last performance of the Surveillance. If the Surveillance has been performed recently, a review of the Surveillance history and equipment performance may be sufficient to support a reasonable expectation that the Surveillance will be met when performed.

For Surveillances that have not been performed for a long period or that have never been performed, a rigorous evaluation based on objective evidence should provide a high degree of confidence that the equipment is OPERABLE. The evaluation should be documented in sufficient detail to allow a knowledgeable individual to understand the basis for the determination.

Failure to comply with specified Frequencies for SRs is expected to be an infrequent occurrence. Use of the delay period established by SR 3.0.3 is a flexibility which is not intended to be used repeatedly to extend Surveillance intervals. While up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or the limit of the specified Frequency is provided to perform the missed Surveillance, it is expected that the missed Surveillance will be performed at the first reasonable opportunity. The determination of the first reasonable opportunity should include consideration of the impact on plant risk (from delaying the Surveillance as well as any plant configuration changes required or shutting the plant down to perform the Surveillance) and impact on any analysis assumptions, in addition to unit conditions, planning, availability of personnel, and the time required to perform the Surveillance. This risk impact should be managed through the program in place to implement 1 O CFR 50.65(a)(4) and its implementation guidance, NRC Regulatory Guide 1.160, "Monitoring the Effectiveness of Maintenance at Nuctear Power Plants."

This Regulatory Guide addresses consideration of temporary and aggregate risk impacts, determination of risk management action thresholds, and risk management action up to and including plant shutdown. The missed Surveillance should be treated as an emergent condition as discussed in the Regulatory Guide. The risk evaluation may use quantitative, qualitative, or blended methods. The degree of depth and rigor of the evaluation should be commensurate with the importance of the component. Missed Surveillances for important components should be analyzed quantitatively. If the results of the risk evaluation B 3.0-17 08/02/23

BASES RPS Instrumentation B 3.3.1.1 APPLICABLE SAFETY ANALYSIS, LCO, and APPLICABILITY (continued)

Cooper channels per trip system for both SDVs, a total of two required channels of each type per trip system, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from these Functions on a valid signal. These Functions are required in MODES 1 and 2, and in MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies, since these are the MODES and other specified conditions when control rods are withdrawn. At all other times, this Function may be bypassed.

8.

Turbine Stop Valve-Closure A temporary footnote is provided to address that the Turbine Stop Valve -

Closure function does not meet channel independence criteria. This condition involves the mechanical separation of position switches on the TSVs. Until the issue is resolved, Conditions A and Bare not required to be entered because of the channel independence condition. This temporary footnote will be in place until startup from RE33.

Closure of the TSVs results in the loss of a heat sink that produces reactor pressure, neutron flux, and heat flux transients that must be limited. Therefore, a reactor scram is initiated at the start of TSV closure in anticipation of the transients that would result from the closure of these valves. The Turbine Stop Valve-Closure Function is the primary scram signal for the turbine trip and feedwater controller failure maximum demand events analyzed in Reference 3. For this event, the reactor scram reduces the amount of energy required to be absorbed and ensures that the MCPR SL is not exceeded.

Turbine Stop Valve-Closure signals are initiated from position switches located on each of the two TSVs. Two independent position switches are associated with each stop valve. Both of the switches from one TSV provide input to RPS trip system A; the two switches from the other TSV provide input to RPS trip system B. Thus, each RPS trip system receives two Turbine Stop Valve-Closure channel inputs from a TSV, each consisting of one position switch assembly with two contacts, each inputting to a relay. The relays provide a parallel logic input to an RPS trip logic channel. The logic for the Turbine Stop Valve-Closure Function is such that both TSVs must be closed to produce a scram. Single valve closure will produce a half scram. This Function must be enabled at THERMAL POWER~ 29.5% RTP as measured by turbine supply pressure. This is accomplished automatically by pressure switches sensing turbine supply pressure; therefore, opening the turbine bypass valves may affect this Function.

B 3.3-16 04/05/24

BASES RPS Instrumentation B3.3.1.1 APPLICABLE SAFETY ANALYSIS, LCO, and APPLICABILITY (continued)

Cooper The Turbine Stop Valve-Closure Allowable Value is selected to detect imminent TSV closure, thereby reducing the severity of the subsequent pressure transient.

Four channels of Turbine Stop Valve-Closure Function, with two channels in each trip system, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function if both TSVs should close. This Function is required, consistent with analysis assumptions, whenever THERMAL POWER is~ 29.5% RTP. This Function is not required when THERMAL POWER is < 29.5% RTP since the Reactor Vessel Pressure-High and the Average Power Range Monitor Neutron Flux-High (Fixed) Functions are adequate to maintain the necessary safety margins.

9.

Turbine Control Valve Fast Closure. DEH Trip Oil Pressure-Low Fast closure of the TCVs results in the loss of a heat sink that produces reactor pressure, neutron flux, and heat flux transients that must be limited. Therefore, a reactor scram is initiated on TCV fast closure in anticipation of the transients that would result from the closure of these valves. The Turbine Control Valve Fast Closure, DEH Trip Oil Pressure-Low Function is the primary scram signal for the generator load rejection event analyzed in Reference 3. For this event, the reactor scram reduces the amount of energy required to be absorbed and ensures that the MCPR SL is not exceeded.

Turbine Control Valve Fast Closure, DEH Trip Oil Pressure-Low signals are initiated by low digital-electrohydraulic control (DEHC) fluid pressure in the emergency trip header for the control valves. There are four pressure switches which sense off the common header, with one pressure switch assigned to each separate RPS logic channel. This Function must be enabled at THERMAL POWER~ 29.5% RTP as measured by turbine supply pressure. This is accomplished automatically by pressure switches sensing turbine supply pressure; therefore, opening the turbine bypass valves may affect this Function.

The Turbine Control Valve Fast Closure, DEH Trip Oil Pressure-Low Allowable Value is selected high enough to detect imminent TCV fast closure.

Four channels of Turbine Control Valve Fast Closure, DEH Trip Oil Pressure-Low Function with two channels in each trip system arranged in a one-out-of-two logic are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. This Function is required, consistent with the analysis 8 3.3-17 04/05/24

BASES RPS Instrumentation B 3.3.1.1 APPLICABLE SAFETY ANALYSIS, LCO, and APPLICABILITY (continued)

Cooper assumptions, whenever THERMAL POWER is ~ 29.5% RTP. This Function is not required when THERMAL POWER is < 29.5% RTP, since the Reactor Vessel Pressure-High and the Average Power Range Monitor Neutron Flux-High (Fixed) Functions are adequate to maintain the necessary safety margins.

10.

Reactor Mode Switch-Shutdown Position The Reactor Mode Switch-Shutdown Position Function provides signals, via the manual scram logic channels, directly to the scram pilot solenoid power circuits. These manual scram logic channels are redundant to the automatic protective instrumentation channels and provide manual reactor trip capability. This Function was not specifically credited in the accident analysis, but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.

The reactor mode switch is a keylock four-position, four-bank switch. The reactor mode switch will scram the reactor if it is placed in the shutdown position. Scram signals from the reactor mode switch are input into each of the two RPS manual scram logic channels.

There is no Allowable Value for this Function, since the channels are mechanically actuated based solely on reactor mode switch position.

Two channels of Reactor Mode Switch-Shutdown Position Function, with one channel in each manual scram trip system, are available and required to be OPERABLE. The Reactor Mode Switch-Shutdown Position Function is required to be OPERABLE in MODES 1 and 2, and MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies, since these are the MODES and other specified conditions when control rods are withdrawn.

11.

Manual Scram The Manual Scram push button channels provide signals, via the manual scram logic channels, directly to the scram pilot solenoid power circuits.

These manual scram logic channels are redundant to the automatic protective instrumentation channels and provide manual reactor trip capability. This Function was not specifically credited in the accident analysis but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.

There is one Manual Scram push button channel for each of the two RPS manual scram logic channels. In order to cause a scram it is necessary that the channel in both manual scram trip systems be actuated.

B 3.3-18 04/05/24

BASES RPS Instrumentation B 3.3.1.1 APPLICABLE SAFETY ANALYSIS, LCO, and APPLICABILITY (continued)

ACTIONS Cooper There is no Allowable Value for this Function since the channels are mechanically actuated based solely on the position of the push buttons.

Two channels of Manual Scram with one channel in each manual scram trip system are available and required to be OPERABLE in MODES 1 and 2, and in MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies, since these are the MODES and other specified conditions when control rods are withdrawn.

A Note has been provided to modify the ACTIONS related to RPS instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable RPS instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable RPS instrumentation channel.

A.1 and A.2 Because of the diversity of sensors available to provide trip signals and the redundancy of the RPS design, an allowable out of service time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> has been shown to be acceptable (Ref. 11) to permit restoration of any inoperable channel to OPERABLE status. However, this out of service time is only acceptable provided the associated Function's inoperable channel is in one trip system and the Function still maintains RPS trip capability (refer to Required Actions B.1, B.2, and C.1 Bases). If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel or the associated trip system must be placed in the tripped condition per Required Actions A.1 and A.2. Placing the inoperable channel in trip (or the associated trip system in trip) would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue. Alternatively, if it is not desired to place the channel (or trip system) in trip (e.g., as in the case where placing the inoperable channel in trip would result in a full scram), Condition D must be entered and its Required Action taken.

B 3.3-19 04/05/24

BASES Control Rod Block Instrumentation B 3.3.2.1 APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

Cooper

1.

Rod Block Monitor The RSM is designed to prevent violation of the MCPR SL and the cladding 1 % plastic strain fuel design limit that may result from a single control rod withdrawal error (RWE) event. The analytical methods and assumptions used in evaluating the RWE event are summarized in Reference 4. A statistical analysis of RWE events was performed to determine the RSM response for both channels for each event. From these responses, the fuel thermal performance as a function of RSM Allowable Value was determined. The Allowable Values are chosen as a function of power level. Based on the specified Allowable Values, operating limits are established.

The RSM Function satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii) (Ref. 5).

Two channels of the RSM are required to be OPERABLE, with their setpoints within the appropriate Allowable Values, to ensure that no single instrument failure can preclude a rod block from this Function. The actual setpoints are calibrated consistent with applicable setpoint methodology.

The RSM is assumed to mitigate the consequences of an RWE event when operating~ 30% RTP (analytical limit) and a peripheral control rod is not selected. Below this power level or if a peripheral control rod is selected, the consequences of an RWE event will not exceed the MCPR SL and, therefore, the RBM is not required to be OPERABLE (Ref 4). When operating< 90% RTP, analyses (Ref. 4) have shown that with an initial MCPR greater than or equal to the limit specified in the COLR, no RWE event will result in exceeding the MCPR SL. Also, the analyses demonstrate that when operating at ~ 90% RTP with MCPR greater than or equal to the limit specified in the COLR, no RWE event will result in exceeding the MCPR SL (Ref. 4). Therefore, under these conditions, the RBM is also not required to be OPERABLE.

2.

Rod Worth Minimizer The RWM is a backup to operator control of the rod sequences. The RWM enforces the banked position withdrawal sequence (BPWS) by alerting the operator when the rod pattern is not in accordance with BPWS. Compliance with BPWS ensures that the initial conditions of the CRDA analysis are not violated.

The analytical methods and assumptions used in evaluating the CRDA are summarized in References 6 and 7. The BPWS requires that control B 3.3-45 10/22/24

BASES Primary Containment Isolation Instrumentation B 3.3.

6.1 BACKGROUND

(continued)

Cooper The exceptions to this arrangement are the Main Steam Line Flow-High Function and Main Steam Tunnel Temperature-High Functions. The Main Steam Line Flow-High Function uses 16 flow channels, four for each steam line. One channel from each steam line inputs to one of the four trip strings. Two trip strings make up each trip system and both trip systems must trip to cause an MSL isolation. Each trip string has four inputs (one per MSL), any one of which will trip the trip string. The trip strings are arranged in a one-out-of-two taken twice logic. This is effectively a one-out-of-eight taken twice logic arrangement to initiate a Group I isolation.

The Main Steam Tunnel Temperature-High Function receives input from 16 temperature switches located in the steam tunnel. These switches are physically located along and in the vicinity of the steam lines in groups of eight (8). There are two locations in the steam tunnel (upper/east and lower/west). For each location, four of the eight switches input into trip system A, the other four into trip system B. The four switches per location are electrically connected in series with switches in the other locations and with normally energized trip relays. Any one switch tripping in its trip system plus any one switch tripping in the other trip system will result in isolation of the MSIVs and MSL drains. For purposes of this specification, each temperature switch is considered a "channel".

2.

Primary Containment Isolation Most Primary Containment Isolation Functions receive inputs from four channels. The outputs from these channels are arranged into two one-out-of-two taken twice trip system logics. One trip system logic initiates isolation of all inboard primary containment isolation valves, while the other trip system logic initiates isolation of all outboard primary containment isolation valves. Each logic closes one of the two valves on each penetration, so that operation of either logic isolates the penetration.

The exception to this arrangement is the Main Steam Line Radiation-High Function. This Function has four channels, whose outputs are arranged in two, two-out-of-two trip system logics for the recirculation sample valves, and in one, one-out-of-two taken twice trip system logic for the mechanical vacuum pump and associated isolation valves. Each of the recirculation sample valve logics isolates one of the two valves. The single mechanical vacuum pump logic must actuate to trip both mechanical vacuum pumps and isolate the associated valves.

The valves isolated by each of the Primary Containment Isolation Functions are listed in Reference 1.

B 3.3-141 11/13/24

BASES Primary Containment Isolation Instrumentation B 3.3.6.1 APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

Cooper of the MSIVs. The closure of the MSIVs is initiated to prevent the addition of steam that would lead to additional condenser pressurization and possible rupture of the diaphragm installed to protect the turbine exhaust hood, thereby preventing a potential radiation leakage path following an accident.

Condenser vacuum pressure signals are derived from four pressure switches that sense the pressure in the condenser. Four channels of Condenser Vacuum-Low Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The Allowable Value is chosen fo prevent damage to the condenser due to pressurization, thereby ensuring its integrity for offsite dose analysis.

As noted (footnote (a) to Table 3.3.6.1-1 ), the channels are not required to be OPERABLE in MODES 2 and 3 when all turbine stop valves (TSVs) are closed, since the potential for condenser overpressurization is minimized. Switches are provided to manually bypass the channels when all TS Vs are closed.

This Function isolates the MSIVs and MSL drains.

1.e.

Main Steam Tunnel Temperature-High The Main Steam Tunnel Temperature-High Function is provided to detect a break in a main steam line and provides diversity to the high flow instrumentation. High temperatures in the Main Steam Tunnel could indicate a breach of a main steam line. The automatic closure of the MSIVs and main steam line drains prevents excessive loss of reactor coolant and the release of significant amounts of radioactive material from the nuclear system process boundary.

Main Steam Tunnel temperature signals are initiated from 16 steam tunnel temperature switch channels. For each physical location of eight channels, two channels per trip system are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The Allowable Value is chosen to detect a leak equivalent to between 1 %

and 10% rated steam flow.

This Function isolates the MSIVs and MSL drains.

B 3.3-148 11/13/24

BASES ACTIONS Cooper RHR Shutdown Cooling System-Hot Shutdown B 3.4.7 A Note has been provided to modify the ACTIONS related to RHR shutdown cooling subsystems. Section 1.3, Completion Times, specifies once a Condition has been entered, subsequent divisions, subsystems, components or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable shutdown cooling subsystems provide appropriate compensatory measures for separate inoperable shutdown cooling subsystems. As such, a Note has been provided that allows separate Condition entry for each inoperable RHR shutdown cooling subsystem.

With one required RHR shutdown cooling subsystem inoperable for decay heat removal, except as permitted by LCO Note 2, the overall reliability is reduced, because a single failure in the OPERABLE subsystem could result in reduced RHR shutdown cooling capability.

Therefore, an alternate method of decay heat removal must be provided.

The required cooling capacity of the alternate method should be sufficient to maintain or reduce temperature. Decay heat removal by ambient losses can be considered as, or contributing to, the alternate method capability. Alternate methods that can be used include (but are not limited to) the Condensate/Main Steam Systems, the Reactor Water Cleanup System, a combination of an ECCS pump and a safety/relief valve, or an inoperable but functional RHR shutdown cooling system.

B.1 If the required alternate method of decay heat removal cannot be verified within one hour, immediate action must be taken to restore the inoperable RHR shutdown cooling subsystem to operable status. The Required Action will restore redundant decay heat removal paths. The immediate Completion Time reflects the importance of maintaining the availability of two paths for heat removal.

C.1 With both required RHR shutdown cooling subsystems inoperable, an alternate method of decay heat removal must be provided in addition to that provided for the initial RHR shutdown cooling subsystem inoperability. This re-establishes backup decay heat removal capabilities, similar to the requirements of the LCO. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time is B 3.4-36 11/15/23

BASES ACTIONS (continued)

Cooper RHR Shutdown Cooling System-Hot Shutdown B 3.4.7 based on the decay heat removal function and the probability of a loss of the available decay heat removal capabilities. Furthermore, verification of the functional availability of these alternate method(s) must be reconfirmed every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter. This will provide assurance of continued heat removal capability.

The required cooling capacity of the alternate method should be sufficient to maintain or reduce temperature. Decay heat removal by ambient losses can be considered as, or contributing to, the alternate method capability. Alternate methods that can be used include (but are not limited to) the Reactor Water Cleanup System, or an inoperable but functional RHR shutdown cooling subsystem.

0.1 If the required alternate methods of decay heat removal cannot be verified within one hour, immediate action must be taken to restore at least one RHR shutdown cooling subsystem to OPERABLE status. The immediate Completion Time reflects the importance of restoring a method of heat removal.

Required Action D.1 is modified by a Note indicating that all required MODE changes to MODE 4 may be suspended until one RHR shutdown cooling subsystem is restored to OPERABLE status. In this case, LCO 3.0.3 and other Required Actions directing entry into MODE 4 could force the unit into a less safe condition in which there may be no adequate means to remove decay heat. It is more appropriate to allow the restoration of one of the RHR shutdown cooling subsystems before requiring entry into a condition in which that subsystem would be needed and exiting a condition where other sources of cooling are available.

When at least one RHR subsystem is restored to OPERABLE status, the Completion Times of LCO 3.0.3 or other Required Actions resume at the point at which they were suspended.

E.1. E.2 1 and E3 With no RHR shutdown cooling subsystem and no recirculation pump in operation, except as permitted by LCO Note 1, reactor coolant circulation by the RHR shutdown cooling subsystem or recirculation pump must be restored without delay.

Until RHR or recirculation pump operation is re-established, an alternate method of reactor coolant circulation must be placed into service. This will provide the necessary circulation for monitoring coolant temperature.

The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time is based on the coolant circulation function 8 3.4-37 11/15/23

BASES ACTIONS (continued)

RHR Shutdown Cooling System-Hot Shutdown B 3.4.7 and is modified such that the 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> is applicable separately for each occurrence involving a loss of coolant circulation. Furthermore, verification of the functioning of the alternate method must be reconfirmed every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter. This will provide assurance of continued temperature monitoring capability.

During the period when the reactor coolant is being circulated by an alternate method ( other than by the required RHR shutdown cooling subsystem or recirculation pump), the reactor coolant temperature and pressure must be periodically monitored to ensure proper function of the alternate method. The once per hour Completion Time is deemed appropriate.

SURVEILLANCE REQUIREMENTS SR 3.4.

7.1 REFERENCES

Cooper This Surveillance verifies that one RHR shutdown cooling subsystem or recirculation pump is in operation and circulating reactor coolant. The required flow rate is determined by the flow rate necessary to provide sufficient decay heat removal capability. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This Surveillance is modified by a Note allowing sufficient time to align the RHR System for shutdown cooling operation after clearing the pressure interlock that isolates the system, or for placing a recirculation pump in operation. The Note takes exception to the requirements of the Surveillance being met (i.e., forced coolant circulation is not required for this initial 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> period), which also allows entry into the Applicability of this Specification in accordance with SR 3.0.4 since the Surveillance will not be 11not met" at the time of entry into the Applicability.

1.

USAR, Appendix G.

2.

10 CFR 50.36( c)(2)(ii).

B 3.4-38 11/15/23

BASES Secondary Containment B 3.6.4.1 SURVEILLANCE REQUIREMENTS SR 3.6.4.1.1 Cooper This SR ensures that the secondary containment boundary is sufficiently leak tight to preclude exfiltration under expected wind conditions.

The SR is modified by a Note which states the SR is not required to be met for up to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> if an analysis demonstrates that one SGT subsystem remains capable of establishing the required secondary containment vacuum. Use of the Note is expected to be infrequent but may be necessitated by situations in which secondary containment vacuum may be less than the required containment vacuum, such as, but not limited to, wind gusts or failure or change of operating normal ventilation subsystems. These conditions do not indicate any change in the leak tightness of the secondary containment boundary. The analysis should consider the actual conditions (equipment configuration, temperature, atmosphere pressure, wind conditions, measured secondary containment vacuum, etc.) to determine whether, if an accident requiring secondary containment to be OPERABLE were to occur, one train of SGT could establish the assumed secondary containment vacuum within the time assumed in the accident analysis. If so, the SR may be considered met for a period up to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> limit is based on the expected short duration of the situations when the Note would be applied.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.6.4.1.2 Verifying that secondary containment equipment hatches are closed ensures that the infiltration of outside air of such a magnitude as to prevent maintaining the desired negative pressure does not occur and provides adequate assurance that exfiltration from the secondary containment will not occur. SR 3.6.4.1.2 also requires equipment hatches to be sealed. In this application, the term "sealed" has no connotation of leak tightness.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.6.4.1.3 Verifying that one secondary containment access door in each access opening is closed provides adequate assurance that exfiltration from the secondary containment will not occur. An access opening contains at B 3.6-73 02/22/24

BASES Secondary Containment B 3.6.4.1 SURVEILLANCE REQUIREMENTS (continued)

REFERENCES Cooper least one inner and one outer door. The intent is to not breach the secondary containment, which is achieved by maintaining the inner or outer portion of the barrier closed except when the access opening is being used for entry and exit.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.6.4.1.4 The SGT System exhausts the secondary containment atmosphere to the environment through appropriate treatment equipment. SR 3.6.4.1.4 demonstrates that one SGT subsystem can maintain ~ 0.25 inches of vacuum water gauge for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> at a flow rates 1780 cfm. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> test period allows secondary containment to be in thermal equilibrium at steady state conditions. Therefore, this test is used to ensure secondary containment boundary integrity. Since this SR is a secondary containment test, it need not be performed with each SGT subsystem.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

1.

USAR, Section XIV-6.3.

2.

USAR, Section XIV-6.4.

3.

10 CFR 50.36(c)(2)(ii).

8 3.6-74 02/22/24

BASES SW System and UHS B 3.7.2 SURVEILLANCE REQUIREMENTS (continued)

REFERENCES Cooper position within the required time. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.

This SR is modified by a Note indicating that isolation of the SW System to components or systems may render those components or systems inoperable, but does not affect the OPERABILITY of the SW System. As such, when all SW pumps, valves, and piping are OPERABLE, but a branch connection off the main header is isolated, the SW System is still OPERABLE.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.7.2.4 This SR verifies that the automatic isolation valves of the SW System will automatically switch to the safety or emergency position to provide cooling water exclusively to the safety related equipment during an accident event This is demonstrated by the use of an actual or simulated initiation signal. The initiation signal is caused by low SW header pressure (approximately 20 psig). This SR also verifies that the SW pumps with their mode selector switch in AUTO will automatically start on a low SW header pressure.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

1.

NEDC 94-255, "Hydraulic Evaluation of Opening in Intake Structure Guide Wall," June 14, 1995.

2.

USAR, Chapter V.

3.

USAR, Chapter XIV.

4.

10 CFR 50.36(c)(2)(ii).

5.

NEDC 00-095E, "CNS Reactor Building Post-LOCA Heating Analysis," June 29, 2023.

B3.7-10 08/02/23

BASES ACTIONS Cooper Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 The ACTIONS Table is modified by a Note indicating that separate Condition entry is allowed for each DG except for Conditions A, C, and D.

This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable DG subsystem.

Complying with the Required Actions for one inoperable DG subsystem may allow for continued operation, and subsequent inoperable DG subsystem( s) governed by separate Condition entry and application of associated Required Actions. The Note does not apply to Conditions A, C and D since the CNS design has two fuel oil storage tanks that supply fuel oil to both DGs.

Note 2 is a temporary note that allows a diesel fuel oil storage tank (FOST) to be made inoperable and drained to support cleaning, inspection, testing, and associated repair activities without entering Conditions A and F if certain conditions are met.

a.

Equipment (temporary transfer pump, hoses, and appropriate fittings) capable of supplying fuel oil to the in-service permanent tank aligned to the operable DG must be available.

A temporary transfer pump with a capacity greater than 15 gpm must be pre-staged and available to transfer the temporary storage tank fuel oil and out-of-service permanent storage tank fuel oil. This is considered sufficient based on fuel in the in-service permanent tank providing a minimum of 4 days full load operation of the DG, contingency measures which pre-stage equipment necessary to supply fuel oil to the in-service permanent tank or directly to the DG day tank, and the initiation of action to obtain replenishment fuel.

b.

The FOSTs and temporary tanks combined will be verified to contain a ?-day supply of fuel oil on a 24-hour frequency.

Periodic verification of the required volume to allow for a 7-day supply of fuel oil to the required DG is essential to meet the licensing basis for DG operation. During fuel movement between the permanent tanks and temporary tanks, the overall fuel oil storage volume contained within all the tanks may be used to meet the 7-day requirement.

c.

Additional compensatory measures that must be met, before and during the maintenance activity, are listed in Attachment 2 of NLS2023029.

These compensatory measures and the temporary fuel oil system ensure the fuel oil volume required for the 7-day requirement is met.

B 3.8-31 08/07/24

BASES Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 ACTIONS (continued)

Cooper

d.

Each FOST may be taken out of service for up to 14 days.

Condition F must be entered if any Note 2 condition is not met or the 14-day completion time is reached.

This temporary note is applicable only during Refuel Outage 33 while in MODES 4 or 5.

In this Condition, the 7 day fuel oil supply for both DGs is not available.

The 49,500 gallon limit is a conservative estimate of the required fuel oil based on worst case fuel consumption. However, the Condition is restricted to fuel oil level reductions that maintain at least a 6 day supply.

The fuel oil level equivalent to a 6 day supply is 42,800 gallons. These circumstances may be caused by events such as:

a.

Full load operation required for an inadvertent start while at minimum required level; or

b.

Feed and bleed operations that may be necessitated by increasing particulate levels or any number of other oil quality degradations.

This restriction allows sufficient time for obtaining the requisite replacement volume and performing the analyses required prior to addition of the fuel oil to the tank. A period of 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> is considered sufficient to complete restoration of the required levet prior to declaring the DGs inoperable. This period is acceptable based on the remaining capacity(> 6 days), the fact that action will be initiated to obtain replenishment, and the low probability of an event during this brief period.

8.1 In this Condition, the 7 day lube oil inventory, i.e., sufficient lube oil to support 7 days of continuous DG operation at full load conditions, is not available. However, the Condition is restricted to lube oil volume reductions that maintain at least a 6 day supply. The lube oil inventory equivalent to a 6 day supply is 432 gallons. This restriction allows sufficient time for obtaining the requisite replacement volume. A period of 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> is considered sufficient to complete restoration of the required volume prior to declaring the DG inoperable. This period is acceptable based on the remaining capacity(> 6 days), the low rate of usage, the fact that action will be initiated to obtain replenishment, and the low probability of an event during this brief period.

B 3.8-32 08/07/24

BASES Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 ACTIONS (continued)

C.1 Cooper This Condition is entered as a result of a failure to meet the acceptance criterion for particulates. Normally, trending of particulate levels allows sufficient time to correct high particulate levels prior to reaching the limit of acceptability. Poor sample procedures (bottom sampling),

contaminated sampling equipment and errors in laboratory analysis can produce failures that do not follow a trend, Since the presence of particulates does not mean failure of the fuel oil to burn properly in the diesel engine, since particulate concentration is unlikely to change significantly between Surveillance Frequency intervals 1 and since proper engine performance has been recently demonstrated (within 31 days), it is prudent to allow a brief period prior to declaring the DGs inoperable.

The 7 day Completion Time a.Hows for further evaluation 1 resampling, and re-analysis of the DG fuel oil.

D.1 With the new fuel oil properties defined in the Bases for SR 3.8.3.3 not within the required limits, a period of 30 days is allowed for restoring the stored fuel oil properties. This period provides sufficient time to test the stored fuel oil to determine that the new fuel oil, when mixed with previously stored fuel oil, remains acceptable, or to restore the stored fuel oil properties. This restoration may involve feed and bleed procedures, filtering, or combination of these procedures. Even if a DG start and load was required during this time interval and the fuel oil properties were outside limits, there ls high likelihood that the DG would still be capable of performing its intended function. If the new fuel has not yet been added to the fuel oil storage tanks, entry into this Condition is not necessary.

E.1 With pressure at least 200 psig in at least one starting air receiver, sufficient capacity for multiple DG start attempts in accordance with References 7 and 9 exists. As long as the pressure is at least 125 psig in at least one starting air receiver, there is capacity for at least one start attempt, and the DG can be considered OPERABLE while the air receiver pressure is restored to the required limit. A period of 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> is considered sufficient to complete restoration to the required pressure prior to declaring the DG inoperable. This period is acceptable based on the remaining air start capacity, the fact that most DG starts are accomplished on the first attempt, and the low probability of an event during this brief period.

B 3.8-33 08/07/24

BASES Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 ACTIONS (continued)

Ll With a Required Action and associated Completion Time of Condition A, B. C, D! or E not met, or the stored diesel fuel oil; lube oil, or starting air subsystem not within limits for reasons other than addressed by Conditions A, B, C, D, or E, the associated DG(s) may be incapable of performing its intended function and must be immediately declared inoperable.

SURVEILLANCE REQUIREMENTS SR 3.8.3.1 Cooper This SR provides verification that there is an adequate inventory of fuel oil in the storage tanks to support a single DG's operation for 7 days at full load. The fuel oil level equivalent to a 7 day supply is 49,500 gallons when calculated in accordance with References 2 and 3. The required fuel storage volume is determined using the most limiting energy content of the stored fuel. Using the known correlation of diesel fuel oil absolute specific gravity or API gravity to energy content, the required diesel generator output, and the corresponding fuel consumption rate, the onsite fuel storage volume required for 7 days of operation can be determined.

SR 3.8.3.3 requires new fuel to be tested to verify that the absolute specific gravity or API gravity is within the range assumed in the diesel fuel oil consumption calculations. The 7 day period is sufficient time to place the unit in a safe shutdown condition and to bring in replenishment fuel from an offsite location.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.8.3.2 This Surveiflance ensures that sufficient lubricating oil inventory

( combined inventory in the DG lube oil sump and in the warehouse) is available to support at least 7 days of operation for one DG. The lube oil inventory equivalent to a 7 day supply is 504 gallons and is based on a 3 gallon per hour consumption value for the run time of the DG. Implicit in this SR is the requirement to verify that adequate DG lube oil is stored onsite to ensure that sump level does not drop below the manufacturer's recommended minimum level.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

B 3.8-34 08/07/24

BASES Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.3.3 Cooper The tests of new fuel oil prior to addition to the storage tanks are a means of determining whether new fuel oil is of the appropriate grade and has not been contaminated with substances that would have an immediate detrimental impact on diesel engine combustion. If results from these tests are within acceptable limits, the fuel oil may be added to the storage tanks without concern for contaminating the entire volume of fuel oil in the storage tanks. These tests are to be conducted prior to adding the new fuel to the storage tank(s), but in no case is the time between the sample (and corresponding test results) including receipt of new fuel and addition of new fuel oil to the storage tanks to exceed 31 days. The tests, limits, and applicable ASTM Standards are as follows:

a.

Sample the new fuel oil in accordance with ASTM D4057-1988 (Ref. 8);

b.

Verify in accordance with the tests specified in ASTM D975-1989a (Ref. 8) that: (1) the sample has an API gravity of within 0.3° at 60°F or a specific gravity of within 0.0016 at 60/60°F, when compared to the supplier's certificate, or the sample has an absolute specific gravity at 60/60°F of c 0.83 and ~ 0.89 or an API gravity at 60°F of c 26° and s; 38° when tested in accordance with ASTM D1298-2012b (Reapproved 2017)81; (2) a kinematic viscosity at 40°C of c 1.9 centistokes and s; 4.1 centistokes, or a Saybolt viscosity at 100°F of~ 32.6 and s; 40.1 if gravity was not determined by comparison with the supplier's certification; and (3) a flash point of;;:; 125°F; and

c.

Verify that the new fuel oil has a clear and bright appearance with proper color when tested in accordance with ASTM D4176-1991 (Ref. 8) or a water and sediment content of s; 0.05% volume when tested in accordance with ASTM D1796-1983 (Ref. 8).

Failure to meet any of the above limits is cause for rejecting the new fuel oil, but does not represent a failure to meet the LCO concern since the fuel oil is not added to the storage tanks.

Following the initial new fuel oil sample, the new fuel oil is analyzed to establish that the other properties specified in Table 1 of ASTM D975-1989a (Ref. 8) are met for new fuel oil when tested in accordance with ASTM O975-1989a (Ref. 8), except that the analysis for sulfur may be performed in accordance with ASTM D1552-1990 (Ref. 8), ASTM D2622-1992 (Ref. 8), or ASTM 04294-2021 (Ref. 8). These additional analyses are required, by Specification 5.5.9, "Diesel Fuel Oil Testing Program," to be performed within 31 days following addition of new fuel oil. This 31 day requirement is intended to assure that:

B 3.8-35 08/28/24

BASES Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 SURVEILLANCE REQUIREMENTS (continued)

Cooper

a.

The new fuel oil sample is taken no more than 31 days old at the time of adding the new fuel oil to the DG storage tank; and

b.

The results of the new fuel oil sample are obtained within 31 days after addition of the new fuel oil to the DG storage tank.

The 31 day period is acceptable because the fuel oil properties of interest, even if they were not within stated limits, would not have an immediate effect on DG operation. This Surveillance ensures the availability of high quality fuel oil for the DGs.

Fuel oil degradation during long term storage shows up as an increase in particulate, mostly due to oxidation. The presence of particulate does not mean that the fuel oil will not burn properly in a diesel engine. The particulate can cause fouling of filters and fuel oil injection equipment, however, which can cause engine failure.

Particulate concentrations should be determined in accordance with ASTM 02276-1989 (Ref. 8), Method A or ASTM 05452-2023 (Ref. 8).

These methods involve a gravimetric determination of total particulate concentration in the fuel oil and have a limit of 10 mg/I. It is acceptable to obtain a field sample for subsequent laboratory testing in lieu of field testing. For the Cooper Nuclear Station design in_ which the total volume of stored fuel oil is contained in two interconnected tanks, each tank must be considered and tested separately.

The Frequency of this test takes into consideration fuel oil degradation trends that indicate that particulate concentration is unlikely to change significantly between Frequency intervals.

SR 3.8.3.4 This Surveillance ensures that, without the aid of the refill compressor, sufficient air start capacity for each DG is available. The system design requirements provide for multiple engine start cycles without recharging.

The pressure specified in this SR is intended to reflect the lowest value at which the requirements of Reference 7 can be satisfied.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.8.3.5 Microbiological fouling is a major cause of fuel oil degradation. There are numerous bacteria that can grow in fuel oil and cause fouling, but all must B 3.8-36 08/28/24

BASES Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 SURVEILLANCE REQUIREMENTS (continued)

REFERENCES Cooper have a water environment in order to survive. Periodic removal of water from the fuel storage tanks eliminates the necessary environment for bacterial survival. This is the most effective means of controlling microbiological fouling. In addition, it eliminates the potential for water entrainment in the fuel oil during 0G operation. Water may come from any of several sources, including condensation, ground water, rain water, contaminated fuel oil, and from breakdown of the fuel oil by bacteria.

Frequent checking for and removal of accumulated water minimizes fouling and provides data regarding the watertight integrity of the fuel oil system. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The presence of water does not necessarily represent failure of this SR, provided the accumulated water is removed to the extent possible during performance of the Surveillance.

1.

USAR, Section Vlll-5.2.

2.

Regulatory Guide 1. 137, Revision 1, October 1979.

3.

ANSI N195, 1976.

4.

USAR, Chapter VI.

5.

USAR, Chapter XIV.

6.

10 CFR 50.36(c)(2)(ii).

7.

USAR, Section Vlll-5.3.3.

8.

ASTM Standards: D4057-1988E1; D975-1989a; D1298-2012b (Reapproved 2017)81; D4176-1991; 01796-1983; 01552-1990; D2622-1992; 04294-2021; 02276-1989; and 05452-2023.

9.

NEDC 11-072, 0GSA Accumulator Sizing Basis B 3.8-37 08/28/24

BASES ACTIONS (continued)

DC Sources - Operating B 3.8.4 reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. The Completion Time to bring the unit to MODE 4 is consistent with the time required in Regulatory Guide 1.93 (Ref. 6).

C.1 With the Division 1 250 V DC electrical power subsystem inoperable, one LPCI subsystem is rendered inoperable. Loss of the Division 2 250 V DC electrical power subsystem renders HPCI and the other LPCI subsystem inoperable. Required Action C.1 therefore requires with one 250 V DC electrical power subsystem inoperable that the associated supported features be declared inoperable immediately. This declaration also requires entry into applicable Conditions and Required Actions for the associated supported features.

SURVEILLANCE REQUIREMENTS SR 3.8.4.1 Cooper Verifying battery terminal voltage while on float charge for the batteries helps to ensure the effectiveness of the charging system and the ability of the batteries to perform their intended function. Float charge is the condition in which the charger is supplying the continuous charge required to overcome the internal losses of a battery (or battery cell) and maintain the battery (or battery cell) in a fully charged state. The voltage requirements are based on the nominal design voltage of the battery and are consistent with the initial voltages assumed in the battery sizing calculations. Terminal voltage while on float charge is determined by multiplying the number of cells in the battery by minimum float voltage for the battery's nominal SG. At CNS, battery cells are designed for a nominal SG of 1.215 +/- 0.005. Minimum cell float voltage for SG of 1.215 is 2.17 volts per cell (Vpc). The 125 VDC systems have 58 cells connected in series and the 250 VDC systems have 120 cells connected in series. Multiplying 2.17 Vpc by 58 cells yields minimum voltage for 125 V batteries of 125.9. Multiplying 2.17 Vpc by 120 cells yields minimum voltage for 250 V batteries of 260.4. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

B 3.8-41 10/23/24